Systems and methods for producing oil and/or gas

ABSTRACT

A method for producing oil and/or gas from an underground formation comprising locating a suitable reservoir in a subsurface formation; creating a model of the reservoir; populating the model with laboratory data; modeling the reservoir to determine fluid displacements based on fluids injected and fluids produced; determining an optimum fluid mixture for the fluids to be injected based on a series of sensitivity analyses performed with the model; drilling a first well in the formation; injecting the optimum fluid mixture into the first well; drilling a second well in the formation; and producing oil and/or gas from the second well.

FIELD OF THE INVENTION

The present disclosure relates to systems and methods for producing oil and/or gas.

BACKGROUND OF THE INVENTION

Enhanced Oil Recovery (EOR) may be used to increase oil recovery in fields worldwide. There are three main types of EOR, thermal, chemical/polymer and gas injection, which may be used to increase oil recovery from a reservoir, beyond what can be achieved by conventional means—possibly extending the life of a field and boosting the oil recovery factor.

Thermal enhanced recovery works by adding heat to the reservoir. The most widely practised form is a steamdrive, which reduces oil viscosity so that can flow to the producing wells. Chemical flooding increases recovery by reducing the capillary forces that trap residual oil and/or by reducing the interfacial tension between oil and water. Polymer flooding improves the sweep efficiency of injected water. Miscible injection works by creating a mixture of the injectant and the oil that flows more easily towards the production well than the oil by itself.

Referring to FIG. 1, there is illustrated prior art system 100. System 100 includes underground formation 102, underground formation 104, underground formation 106, and underground formation 108. Production facility 110 is provided at the surface. Well 112 traverses formations 102 and 104, and terminates in formation 106. The portion of formation 106 is shown at 114. Oil and gas are produced from formation portion 114 through well 112, to production facility 110. Gas and liquid are separated from each other, gas is stored in gas storage 116 and liquid is stored in liquid storage 118.

U.S. Pat. No. 6,022,834 discloses a concentrated surfactant formulation and process for the recovery of residual oil from subterranean petroleum reservoirs, and more particularly an alkali surfactant flooding process which results in ultra-low interfacial tensions between the injected material and the residual oil, wherein the concentrated surfactant formulation is supplied at a concentration above, at, or, below its CMC, also providing in situ formation of surface active material formed from the reaction of naturally occurring organic acidic components with the injected alkali material which serves to increase the efficiency of oil recovery. U.S. Pat. No. 6,022,834 is herein incorporated by reference in its entirety.

U.S. Pat. No. 5,068,043 discloses an aqueous alkaline flood for recovering oil from a reservoir containing acidic oil which includes adding to the injected aqueous alkaline solution both a stoichiometric excess of the alkaline material and a kind and amount of preformed cosurfactant material that increases the salinity of that solution so that, in contact with the oil in the reservoir, it will form a surfactant system having a salinity requirement which minimizes the interfacial tension between it and the oil. U.S. Pat. No. 5,068,043 is herein incorporated by reference in its entirety.

U.S. Patent Application Publication Number 2009/0194276, published Aug. 6, 2009, discloses systems and methods for the determination of an optimum salinity type and an optimum salinity of a surfactant microemulsion system. Optimum salinity type and optimum salinity in surfactant/polymer flooding is determined by core-flood experiments so that a variety of multiphase flow parameters such as relative permeability and phase trapping that affects oil recovery factor, influences the determination of the optimum salinity type and optimum salinity. The optimum salinity determined preferably corresponds to the highest oil recovery factor. U.S. Patent Application Publication Number 2009/0194276 is herein incorporated by reference in its entirety.

U.S. Patent Application Publication Number 2009/0194281, published Aug. 6, 2009, discloses an optimum salinity profile in surfactant/polymer flooding from formation water to post-flush drive that leads to the highest oil recovery factor. The optimum salinity determined from core-flooding experiments may be used in the surfactant slug. The surfactant slug is protected from deterioration by the injection of cushion slugs immediately before and after the injection of the surfactant slug in a reservoir wherein the cushion slugs have the same salinity or about the same salinity as the surfactant slug. A salinity lower may be used in the post-flush drive, while formation water could be of any salinity. U.S. Patent Application Publication Number 2009/0194281 is herein incorporated by reference in its entirety.

There is a need in the art for improved systems and methods for enhanced oil recovery. There is a further need in the art for improved systems and methods for enhanced oil recovery using an alkali surfactant polymer (ASP) flood, for example through increased viscosity of the injectant, reduced interfacial tension of the injectant and the oil, formation of an emulsion with the injectant and the oil, and/or other chemical effects. There is a further need in the art for improved systems and methods for ASP flooding.

SUMMARY OF THE INVENTION

In one aspect, the invention provides a method for producing oil and/or gas from an underground formation comprising locating a suitable reservoir in a subsurface formation; creating a model of the reservoir; populating the model with laboratory data; modeling the reservoir to determine fluid displacements based on fluids injected and fluids produced; determining an optimum fluid mixture for the fluids to be injected based on a series of sensitivity analyses performed with the model; drilling a first well in the formation; injecting the optimum fluid mixture into the first well; drilling a second well in the formation; and producing oil and/or gas from the second well.

Advantages of the invention include one or more of the following:

Improved systems and methods for enhanced recovery of hydrocarbons from a formation with an ASP flood.

Improved systems and methods for enhanced recovery of hydrocarbons from a formation with a fluid containing an ASP flood.

Improved compositions and/or techniques for secondary and/or tertiary recovery of hydrocarbons.

Improved systems and methods for enhanced oil recovery.

Improved systems and methods for enhanced oil recovery using an ASP flood.

Improved systems and methods for enhanced oil recovery using a compound which has an increased viscosity and a lowered interfacial tension compared to water.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates an oil and/or gas production system.

FIG. 2 a illustrates a well pattern.

FIGS. 2 b and 2 c illustrate the well pattern of FIG. 2 a during enhanced oil recovery processes.

FIG. 3 illustrates oil and/or gas production systems.

FIG. 4 illustrates a well pattern.

FIG. 5 illustrates mixtures of crude oil and brine.

FIG. 6 illustrates mixtures of crude oil and brine.

FIG. 7 illustrates results of a core flood experiment.

FIG. 8 illustrates results of a core flood experiment.

FIG. 9 illustrates results of a core flood experiment.

FIG. 10 illustrates a simulation of a pilot ASP flood.

FIG. 11 illustrates a relationship between the optimal salinity of a surfactant and the optimal salinity of a soap.

FIG. 12 illustrates the partitioning of soap and surfactant based on salinity.

FIG. 13 illustrates the results of a well log.

FIG. 14 illustrates field data from a Single-Well Chemical tracer test.

FIG. 15 illustrates field data from a Single-Well Chemical tracer test.

FIG. 16 illustrates a simulation of a pilot ASP flood.

DETAILED DESCRIPTION OF THE INVENTION

FIG. 2 a:

Referring now to FIG. 2 a, in some embodiments, an array of wells 200 is illustrated. Array 200 includes well group 202 (denoted by horizontal lines) and well group 204 (denoted by diagonal lines).

Array 200 defines a production area, enclosed by the rectangle. Array 200 defines an interior of the system. Exterior to array 200 may be located a plurality of containment wells 250.

Each well in well group 202 has horizontal distance 230 from the adjacent well in well group 202. Each well in well group 202 has vertical distance 232 from the adjacent well in well group 202.

Each well in well group 204 has horizontal distance 236 from the adjacent well in well group 204. Each well in well group 204 has vertical distance 238 from the adjacent well in well group 204.

As shown in FIG. 2 a, horizontal distance 230 and horizontal distance 236 refer to a distance from left to right of the paper, and vertical distance 232 and vertical distance 238 refer to a distance from up to down of the paper. In practice, array may be composed of vertical wells that are perpendicular to the earth's surface, horizontal wells that are parallel to the earth's surface, or wells that are inclined at some other angle, for example 30 to 60 degrees with respect to the earth's surface.

Each well in well group 202 is distance 234 from the adjacent wells in well group 204. Each well in well group 204 is distance 234 from the adjacent wells in well group 202.

In some embodiments, each well in well group 202 is surrounded by four wells in well group 204. In some embodiments, each well in well group 204 is surrounded by four wells in well group 202.

In some embodiments, horizontal distance 230 is from about 25 to about 1000 meters, or from about 30 to about 500 meters, or from about 35 to about 250 meters, or from about 40 to about 100 meters, or from about 45 to about 75 meters, or from about 50 to about 60 meters.

In some embodiments, vertical distance 232 is from about 25 to about 1000 meters, or from about 30 to about 500 meters, or from about 35 to about 250 meters, or from about 40 to about 100 meters, or from about 45 to about 75 meters, or from about 50 to about 60 meters.

In some embodiments, horizontal distance 236 is from about 25 to about 1000 meters, or from about 30 to about 500 meters, or from about 35 to about 250 meters, or from about 40 to about 100 meters, or from about 45 to about 75 meters, or from about 50 to about 60 meters.

In some embodiments, vertical distance 238 is from about 25 to about 1000 meters, or from about 30 to about 500 meters, or from about 35 to about 250 meters, or from about 40 to about 100 meters, or from about 45 to about 75 meters, or from about 50 to about 60 meters.

In some embodiments, distance 234 is from about 15 to about 750 meters, or from about 20 to about 500 meters, or from about 25 to about 250 meters, or from about 30 to about 100 meters, or from about 35 to about 75 meters, or from about 40 to about 50 meters.

In some embodiments, array of wells 200 may have from about 10 to about 1000 wells, for example from about 5 to about 500 wells in well group 202, and from about 5 to about 500 wells in well group 204. Optionally, there may be provided from about 2 to about 1000 containment wells 250, for example from about 5 to about 500, or from about 10 to about 200.

In some embodiments, array of wells 200 is seen as a top view with well group 202 and well group 204 being vertical wells spaced on a piece of land. In some embodiments, array of wells 200 is seen as a cross-sectional side view with well group 202 and well group 204 being horizontal wells spaced within a formation.

The recovery of oil and/or gas with array of wells 200 from an underground formation may be accomplished by any known method. Suitable methods include subsea production, surface production, primary, secondary, or tertiary production.

The selection of the method used to recover the oil and/or gas from the underground formation is not critical.

In some embodiments, the containment of oil and/or gas and/or an enhanced oil recovery agent with containment wells 250 may be accomplished by any known method. Suitable methods include pumping water, steam, produced connate water, sea water, carbon dioxide, natural gas or other gaseous or liquid hydrocarbons, nitrogen, air, brine, or other liquids or gases into containment wells 250. In another embodiment, containment wells 250 may be used to create a freeze wall barrier. One suitable freeze wall barrier is disclosed in U.S. Pat. No. 7,225,866 is herein incorporated by reference in its entirety. The selection of the method used to contain oil and/or gas and/or an enhanced oil recovery agent with containment wells 250 is not critical.

In some embodiments, oil and/or gas may be recovered from a formation into a well, and flow through the well and flowline to a facility. In some embodiments, enhanced oil recovery, with the use of an ASP mixture for example a mixture of water, an alkali, a surfactant, and a polymer, may be used to increase the flow of oil and/or gas from the formation.

FIG. 2 b:

Referring now to FIG. 2 b, in some embodiments, array of wells 200 is illustrated. Array 200 includes well group 202 (denoted by horizontal lines) and well group 204 (denoted by diagonal lines). Optional containment wells 250 are provided about array of wells 200.

In some embodiments, an ASP mixture is injected into well group 204, and oil is recovered from well group 202. As illustrated, the ASP mixture has injection profile 208, and oil recovery profile 206 is being produced to well group 202. In some embodiments, a containment agent is injected into containment wells 250. As illustrated, the containment agent has an injection profile about each of the containment wells 250. Containment agent may be used to force ASP mixture and/or oil and/or gas towards producing well group 202.

In some embodiments, ASP mixture is injected into well group 202, and oil is recovered from well group 204. As illustrated, the ASP mixture has injection profile 206, and oil recovery profile 208 is being produced to well group 204. In some embodiments, a containment agent is injected into containment wells 250. As illustrated, the containment agent has an injection profile about each of the containment wells 250. Containment agent may be used to force ASP mixture and/or oil and/or gas towards producing well group 204.

In some embodiments, well group 202 may be used for injecting an ASP mixture, and well group 204 may be used for producing oil and/or gas from the formation for a first time period; then well group 204 may be used for injecting an ASP mixture, and well group 202 may be used for producing oil and/or gas from the formation for a second time period, where the first and second time periods comprise a cycle.

In some embodiments, an ASP mixture or a mixture including an ASP mixture may be injected at the beginning of a cycle, and water optionally with added polymer may be injected at the end of the cycle to push the ASP mixture towards the producing wells. In some embodiments, the beginning of a cycle may be the first 10% to about 80% of a cycle, or the first 20% to about 60% of a cycle, the first 25% to about 40% of a cycle, and the end may be the remainder of the cycle.

In some embodiments, water optionally with added polymer may be used as a containment agent and injected into containment wells 250.

In some embodiments, ASP mixtures injected into the formation may be recovered from the produced oil and/or gas and re-injected into the formation.

In some embodiments, oil as present in the formation prior to the injection of any enhanced oil recovery agents has a viscosity of at least about 5 centipoise, or at least about 10 centipoise, or at least about 25 centipoise, or at least about 50 centipoise, or at least about 75 centipoise, or at least about 90 centipoise. In some embodiments, oil as present in the formation prior to the injection of any enhanced oil recovery agents has a viscosity of up to about 125 centipoise, or up to about 200 centipoise, or up to about 500 centipoise, or up to about 1000 centipoise.

FIG. 2 c:

Referring now to FIG. 2 c, in some embodiments, array of wells 200 is illustrated. Array 200 includes well group 202 (denoted by horizontal lines) and well group 204 (denoted by diagonal lines). Containment wells 250 are located exterior to array 200 to form a perimeter about array 200.

In some embodiments, an ASP mixture is injected into well group 204, and oil is recovered from well group 202. As illustrated, the ASP mixture has injection profile 208 with overlap 210 with oil recovery profile 206, which is being produced to well group 202. In some embodiments, a containment agent is injected into containment wells 250. As illustrated, the containment agent has an injection profile about each of the containment wells 250. Containment agent may be used to force ASP mixture and/or oil and/or gas towards producing well group 202. After a sufficient period of time containment agent injection profile may overlap with one or more of injection profile 208 and oil recovery profile 206 so that enhanced oil recovery agent is contained within array 200; and/or so that oil and/or gas is contained within array 200; and/or so that containment agent is produced to well group 202.

In some embodiments, an ASP mixture is injected into well group 202, and oil is recovered from well group 204. As illustrated, the ASP mixture has injection profile 206 with overlap 210 with oil recovery profile 208, which is being produced to well group 204. In some embodiments, a containment agent is injected into containment wells 250. As illustrated, the containment agent has an injection profile about each of the containment wells 250. Containment agent may be used to force ASP mixture and/or oil and/or gas towards producing well group 204. After a sufficient period of time containment agent injection profile may overlap with one or more of injection profile 208 and oil recovery profile 206 so that enhanced oil recovery agent is contained within array 200; and/or so that oil and/or gas is contained within array 200; and/or so that containment agent is produced to well group 204.

Releasing at least a portion of the ASP mixture and/or other liquids and/or gases may be accomplished by any known method. One suitable method is injecting the ASP mixture into a first well, and pumping out at least a portion of the ASP mixture with gas and/or liquids through a second well. The selection of the method used to inject at least a portion of the ASP mixture and/or other liquids and/or gases is not critical.

In some embodiments, the ASP mixture and/or other liquids and/or gases may be pumped into a formation at a pressure up to the fracture pressure of the formation.

In some embodiments, the ASP mixture may be mixed in with oil and/or gas in a formation to form a mixture which may be recovered from a well.

In some embodiments, a quantity of the ASP mixture may be injected into a well, followed by another component to force the ASP mixture across the formation. For example water in liquid or vapor form, water with a dissolved polymer to increase its viscosity, carbon dioxide, other gases, other liquids, and/or mixtures thereof may be used to force the ASP mixture across the formation.

In some embodiments, from about 0.1 to about 5 pore volumes of the ASP mixture may be injected, for example from about 0.2 to about 2 pore volumes, or from about 0.3 to about 1 pore volumes of the ASP mixture may be injected. The injection of the ASP mixture may be followed by from about 2 to about 10 pore volumes of a polymer water mixture, for example from about 3 to about 8 pore volumes of the polymer-water mixture. The inject of a polymer water mixture may be followed with water from about 1 to about 10 pore volumes.

FIG. 3:

Referring now to FIG. 3, in some embodiments of the invention, system 400 is illustrated. System 400 includes underground formation 402, formation 404, formation 406, and formation 408. Production facility 410 is provided at the surface. Well 412 traverses formation 402 and 404 has openings at formation 406. Portions of formation 414 may be optionally fractured and/or perforated. As oil and gas is produced from formation 406 it enters portions 414, and travels up well 412 to production facility 410. Gas and liquid may be separated, and gas may be sent to gas storage 416, and liquid may be sent to liquid storage 418. Production facility 410 is able to mix, produce and/or store ASP mixture, which may be produced and stored in production/storage 430.

ASP mixture is pumped down well 432, to portions 434 of formation 406. ASP mixture traverses formation 406 to aid in the production of oil and gas, and then the ASP mixture, oil and/or gas may all be produced to well 412, to production facility 410. ASP mixture may then be recycled, for example by utilizing a oil-water gravity separator, centrifuge, demulsifiers, boiling, condensing, filtering, and other separation methods as are known in the art, then re-injecting the ASP mixture into well 432.

Containment well 450 with injection mechanism 452 and containment well 460 with injection mechanism 462 may be provided to contain ASP mixture between containment well 450 and containment well 460. Injection mechanisms 452 and 462 may be used to inject a containment agent, for example a refrigerant to create a freeze wall, or a liquid or gas such as water, water mixed with a viscosifier, water mixed with an alkali, water mixed with a surfactant, carbon dioxide, natural gas, other C₁-C₁₅ hydrocarbons, nitrogen, or air, or mixtures thereof.

In some embodiments, a quantity of ASP mixture or ASP mixture mixed with other components may be injected into well 432, followed by another component to force ASP mixture or ASP mixture mixed with other components across formation 406, for example water in gas or liquid form; water mixed with one or more salts, polymers, alkalis, and/or surfactants; carbon dioxide; other gases; other liquids; and/or mixtures thereof.

In one embodiment, from about 0.1 to about 2, for example from about 0.25 to about 1 pore volumes of ASP mixture may be injected into well 432. Then from about 0.5 to about 10, for example from about 1 to about 5 pore volumes of a polymer-water mixture having a viscosity within about 25%, for example within about 10% of the viscosity of the ASP mixture may be injected into well 432. Then from about 1 to about 10 pore volumes of water may be injected into well 432.

In some embodiments, well 412 which is producing oil and/or gas is representative of a well in well group 202, and well 432 which is being used to inject ASP mixture is representative of a well in well group 204.

In some embodiments, well 412 which is producing oil and/or gas is representative of a well in well group 204, and well 432 which is being used to inject ASP mixture is representative of a well in well group 202.

FIG. 4:

Figure for illustrates a process 500 to design an ASP flood. Process 500 includes determining the optimum salinity for the surfactant 502, determining the optimum salinity for the soap 504, determining the viscosity of the mixture due to the added polymer 506, creating a model for the ASP flood including formation, chemical, and oil properties 508, correlating the model with known data 510, and designing the ASP flood using the model 512. Further details of each of the steps will be set forth below.

The ASP process is a combination of two earlier chemical flooding techniques: the surfactant-polymer flood and the alkaline flood. The task of the chemicals injected in these processes is two-fold: firstly, to reduce the interfacial tension between oil and water in order to liberate oil trapped by capillary forces; and secondly, to stabilise the displacement, when necessary, by increasing the water viscosity through the addition of a polymer. In the case of a surfactant-polymer flood, the reduction of the interfacial tension is achieved by the injected surfactant. In the case of the alkaline flood, the alkali (e.g. NaOH or Na2CO3) raises the pH of the brine which, in turn, leads to a saponification of crude-borne oleic acids to generate a natural surfactant in-situ, commonly referred to as “soap.”

While the injected surfactant (in the following referred to in short as “the surfactant”) and the in-situ generated surfactant (referred to as “the soap”) are chemically rather different, they share the general property that their interfacial activity depends on the environment, for example on salinity. At otherwise constant external conditions, there exists an optimum brine salinity at which the surfactant or the soap reduce the oil-water interfacial tension most strongly.

At lower salinities (“under-optimum regime”) or at higher salinities (“over-optimum regime”) the reduction of interfacial tension is less. In the under-optimum regime, the surfactant and the soap partition favourably into the brine phase; in the over-optimum regime they partition favourably into the oil phase; only near their respective optimum salinities are they able to generate a third, separate “micro-emulsion” phase that exhibits very low interfacial tensions with both the water and the oil phases. The optimum salinity is surfactant-specific; the optimum salinity of soap is generally significantly lower than that of typical injected surfactants

The ASP mixture may be designed such that the optimum salinity of the chemical slug is at or close to the actual brine salinity of the injected water in order to achieve a low oil-water interfacial tension. A high or a low salinity will cause the surfactant or the soap to be pushed ineffectively to the producing wells (under-optimum case) or to be partitioned into immobile oil, i. e. to be retained, and thus lost (over-optimum case).

The ASP mixture may include alkali, surfactant and polymer which are injected together as one slug. In this slug, the alkali and the surfactant will generally travel at (slightly) different velocities: the surfactant is subject to partitioning into any remaining oil and to matrix adsorption while the alkali is consumed by the saponification, by precipitation of carbonates and possibly by exchange reactions with the matrix.

As injected, the phase behaviour of the ASP slug is under-optimum or near optimum. Then, upon contact of the alkali with crude oil, the saponification process leads to a reduction of the optimum salinity in the region where soap is generated such that the phase behaviour locally changes to over-optimum. As a consequence, a gradient in optimum salinity from over-optimum at the front of the chemical slug to (under-)optimum at the rear of the chemical slug establishes which serves to confine the chemical slug and limit dispersive dilution. This inherent gradient can be progressed through the reservoir, moving, in principle, an optimally interfacially active zone though the reservoir which leaves no oil behind.

Determining the Surfactant Phase Optimum Salinity:

In order to determine the chemical phase behavior of a surfactant, an array of samples with different concentrations of alkali and sodium chloride, for example test tubes may be used. One such example, at zero alkali concentration, from which the optimum salinity of the pure surfactant solution can be inferred as shown in FIG. 5. The test tubes which generate a separate emulsion phase may be inferred to be at or near the optimum salinity such that the interfacial tension reduction is at a maximum.

Determining the Soap Phase Optimum Salinity:

In order to determine the chemical phase behavior of a soap follows essentially the same procedure as the surfactant determination, albeit with one complication: The soap is a reactive product of alkali or, more specifically, hydroxide with oleic acid. As such, the amount of soap generated is dependent on the amount of alkali added to the brine.

Adding alkali, however, also raises the salinity such that the behaviour at low salinity combined with high soap concentration cannot be studied. Using sodium carbonate for the alkali, the equilibrium reactions that govern saponification are, in its most simple form, the aqueous reactions:

Na₂CO₃→2Na⁺CO₃ ²⁻  (Equation 1)

CO₃ ²⁻+H₂O

HCO₃ ²⁻+OH⁻  (Equation 2)

and the saponification reaction:

HA_(o)+OH⁻

A⁻+H₂O   (Equation 3)

In equation 3, HA_(o) represents the oil-borne acids and A⁻ represents the soap. Since HA_(o)+OH⁻ reside in oil and water, respectively, the latter reaction is understood to occur at the interface between oil and water.

Depending on the “total acid number” (TAN) of the oil, a quantity that measures the molar concentration of acid in oil, different amounts of alkali are required to establish complete saponification. A comparison of the molar concentrations of carbonate and acid can indicate whether saponification can occur to a significant degree in a given mixture of oil and brine.

Determining the Polymer Solution Viscosity:

In order to determine the polymer solution viscosity, samples with varying salinities may have a given volume of polymer added to them, and then the viscosity of the samples determined. Generally, increasing salinity leads to a lower viscosity, while an increased volume of polymer leads to a higher viscosity.

In one embodiment, the mobility ratio of the ASP mixture is matched to the oil in the formation. In general, the mobility ratio of the ASP mixture and of the oil is a function of the viscosity. Therefore, polymer is added to the ASP mixture until the viscosity of the mixture is similar to that of the oil. In one embodiment, the ASP mixture has a viscosity value within 50% of the viscosity value of the oil, for example within 20%, or within 10%.

Model Setup:

In short, the model is a two-phase (water and oil) multi-component (surfactant, acid, soap, polymer, aqueous chemistry) description of the ASP process including brine chemistry, compositionally dependent partitioning of the chemicals, adsorption and viscosity modification.

The model contains two liquid phases (water and oil) over which it partitions the surfactant and the soap depending on the ratio of salinity versus optimum salinity, and one stationary solid phase.

One central feature of an ASP mixture discussed above is the transition from over-optimum behavior (soap-rich zone) to under-optimum behaviour (surfactant-rich zone). As the ratio of soap to surfactant concentration varies at a given position in the reservoir, so must the optimum salinity. The individual optimum salinities for the surfactant and the soap are taken as input parameters that may be determined experimentally.

Both the surfactant and the soap are allowed to partition over water and oil as a function of the local chemical concentrations (phase composition). This partitioning determines the flow of the surfactant and the soap. Underlying the partitioning model is the qualitative observation that the surfactant and the soap partition strongly into either water or oil as the local composition is under-optimum or over-optimum, respectively. At optimum salinity, however, surfactant and soap partition into both water and oil in equal parts. Since an ASP flood may be over-optimum ahead of the surfactant bank and under-optimum inside the bank, the exact nature of the partitioning coefficient may be less relevant.

An interfacial tension correlation is provided in the model. This correlation assumes that a user-defined minimum interfacial tension is obtained at optimum salinity. Moreover, at a high ratio of soap to surfactant concentration, a minimum interfacial tension due to the soap is established. Finally, minimum interfacial tension can only be achieved if the total surfactant concentration (i.e. the sum of the surfactant and soap concentrations) is at or above the critical micelle concentration. As the total concentration of soap and surfactant is reduced, the interfacial tension gradually approaches the unmodified oil-water value.

The model has a viscosity model taking into account viscosity dependence on polymer mass fraction in water and on effective salinity.

The extent of saponification depends on the local concentration of alkali. Therefore, tracking this as well as the concentrations of acid and other components that affect the soap generation is a feature of the ASP model. The number of reactants may be kept as small as possible in order not to inflate simulation time, involving the saponification equations set forth above.

The complexity of an ASP flood and of the ASP model alongside with the necessary simplifications of the model require a validation of the forecasts generated by the model. To this end, detailed one-dimensional simulations may be carried out and the resulting chemical and production profiles compared to other models or other known data. Thereafter, experimental ASP core flood data may be history matched in order to correlate the model with the data generated by the core-floods. The model may then be further improved by using field trial and commercial scale data obtained from a reservoir.

Designing an ASP Mixture

Once the model has been successfully designed and the parameters set for a given field or formation, the model may be used to determine the components for an ASP mixture. Given the complexity of the number of parameters and the complex chemistry, one suitable starting point would be a previously used ASP mixture chemistry, or to use the optimum mixture chemistry determined from the laboratory experiments discussed above. From there, the salinity of the mixture can be varied, as well as the concentration of surfactant, the concentration of polymer, and the concentration of alkali can be varied. The model may require further calibration with the use of additional lab tests and experiments in order to properly model varied salinity, surfactant concentration, polymer concentration, and/or alkali concentration.

In one embodiment, a sensitivity analysis for the surfactant concentration may be completed first to achieve the optimum surfactant concentration, followed by the same analysis for the alkali, then the polymer. However, the order is not critical.

In general, the incremental oil recovery is compared to the cost of the chemicals to come up with the optimum mixture.

Alternatives:

In some embodiments, oil and/or gas produced may be transported to a refinery and/or a treatment facility. The oil and/or gas may be processed to produce commercial products such as transportation fuels such as gasoline and diesel, heating fuel, lubricants, chemicals, and/or polymers. Processing may include distilling and/or fractionally distilling the oil and/or gas to produce one or more distillate fractions. In some embodiments, the oil and/or gas, and/or the one or more distillate fractions may be subjected to a process of one or more of the following: catalytic cracking, hydrocracking, hydrotreating, coking, thermal cracking, distilling, reforming, polymerization, isomerization, alkylation, blending, and dewaxing.

EXAMPLES

The route from the design of a suitable ASP formulation to actual piloting in the field, to evaluate and demonstrate the feasibility of an ASP project in a giant sandstone reservoir.

Laboratory Work and Model Calibration

A suite of laboratory experiments is required to quantify the behaviour of an ASP formulation. Initially, the phase behaviour of the surfactant mixture and the polymer viscosity behaviour are analysed independently. Thereafter, the two are combined in a core-flood experiment to study oil recovery for a given combination, and to calibrate a flow simulation for subsequent forecasting.

Phase Behaviour Experiments

For the present purpose, the surfactant mixture may be considered as consisting of two independent species: the manufactured injected surfactant and the in-situ generated petroleum soaps. Although these two are, in principle, of rather different molecular structure, they share the ability to reduce the interfacial tension between crude oil and brine, albeit at different brine salinities, all other thermodynamic properties assuming to be determined by the reservoir. The salinity at which a given surfactant achieves the lowest interfacial tension is referred to as its optimum salinity. A low interfacial tension promotes the generation of an oil-brine emulsion phase, which, in turn, may be used as evidence for the achievement of optimum salinity. Along with the interfacial activity, the partitioning of a surfactant between the oil, brine and emulsion phases depends on salinity: at optimum salinity the surfactant partitions into the emulsion phase; at a salinity lower than the optimum salinity (under-optimum case) the surfactant partitions predominantly into brine; at a salinity higher than the optimum salinity (over-optimum case) the surfactant partitions predominantly into oil.

Petroleum soaps originate from naturally occurring petroleum acids, which are saponified by raising the alkalinity of the brine (pH) through the addition of an alkali, such as sodium hydroxide or sodium carbonate. As such, however, the intentional saponification comes jointly with an unintentional rise in salinity (sodium concentration) with a possibility of rendering the environment for the generated petroleum soaps over-optimum, i.e. less effective in reducing oil-water interfacial tension. This interdependence means that plain alkali floods can be difficult to control. Manufactured surfactants, on the other hand, can be tailored to a desired optimum salinity. Originating from industrial chemical synthesis, these molecules are, however, significantly more costly than petroleum soaps which come at the cost of the injected alkali only. Moreover, a dominant loss mechanism for manufactured surfactants is adsorption to the reservoir rock.

Mixtures of surfactants with different optimum salinities are known to exhibit a combined optimum salinity that obeys a simple concentration-dependent mixing rule. With this extra degree of freedom, ASP formulations can be designed that make use of the potential of the petroleum soaps (if present) while guaranteeing optimum phase behaviour through the choice of the manufactured surfactant. As an additional benefit, the presence of alkali reduces the tendency of the manufactured surfactant to adsorb, thereby reducing the required amount of this valuable ingredient.

The optimum salinity behaviour of the petroleum soaps alone can be determined by test tube experiments where oil and brine are combined in different ratios, and where alkali is subsequently added in varying concentrations. One such set of test tubes is displayed in FIG. 5 from which the optimum salinity of the petroleum soaps of the particular crude can be inferred to be about 0.22 mol/l Na⁺. An independent but similar analysis for a manufactured surfactant mixture selected for this particular crude resulted in a value of 0.76 mol/l Na⁺. Error! Reference source not found. shows an alkali scan using oil and brine at a volume ratio of 50/50. The brine contains 0.3 wt. % of the manufactured surfactant mixture. From the existence of the large emulsion phase at a concentration of 1.25 wt. % Na₂CO₃ the optimum salinity for the combination of surfactants and petroleum soaps can be inferred to be 0.31 mol/l Na⁺, i.e. in-between the individual values of the petroleum soaps and the manufactured surfactant mixture.

Core Flood Experiments

Following the demonstration of optimum phase behaviour, an ASP formulation is tested in core flood experiments to prove its ability to liberate and mobilise remaining oil. These experiments provide information about the adsorption characteristics of the chemical components as well as the displacement stability of the (internal) polymer drive. Error! Reference source not found. through Error! Reference source not found. show experimental data of a core flood carried out on a 30 cm long outcrop sandstone core with a diameter of 5 cm. The flooding sequence in this experiment was as follows: a 2.2 PV waterflood; a 0.3 PV ASP flood; a 2.6 PV polymer drive. The ASP formulation consisted of 0.3 wt. % manufactured surfactant, 1 wt. % Na₂CO₃, and a 27 mPa.s polymer solution. The polymer drive also had a viscosity of 27 mPa.s.

The injection pump pressure along with the effluent oil cut and recovery factor are displayed in Error! Reference source not found. 7, clearly showing the production of an oil-bank between 2.6 PV and 3.4 PV injected, at the end of which 98% of the initial present oil has been recovered. Comparing this to the carbonate-bicarbonate effluent concentrations and pH (Error! Reference source not found. 8) as well as the effluent surfactant concentration and viscosity (Error! Reference source not found. 9) reveals that, while the first half of this oil bank is produced as “clean” oil, the second half is emulsified and contains ASP chemicals. The conversion of carbonate to bicarbonate, observed as a temporary increase of the bicarbonate concentration around 3 PV in Error! Reference source not found. 8, is reminiscent of two chemical processes occurring in the porous medium: the saponification of petroleum acids, and clay exchange. In the simulation, these are represented by the following small set of reactions:

-   -   1. Carbonate-bicarbonate balance:

CO₃ ²⁻H₂O

HCO₃ ⁻+OH⁻

-   -   2. Saponification of petroleum acids (HA_(o)) to soaps (A⁻):

HA_(o)+OH⁻

A⁻+H₂O

-   -   3. Exchange of sodium for clay-bound hydrogen:

Na⁺+ H ⁺+OH⁻

Na ^(++H) ₂O

This set is considered to be sufficient unless the behaviour at pH values below 8 must be accurately reproduced, which would require inclusion of the carbonic acid dissociation reaction, or if the brine hardness (concentration of Ca²⁺ and Mg²⁺) is significant enough to precipitate carbonate scale.

The effluent surfactant concentration (Error! Reference source not found. 9) allows determining the adsorption characteristics of the surfactant by way of its breakthrough time. For the present case, a maximum adsorption as low as 2 μg (amount of surfactant per amount of porous medium) was found, representative for the very clean outcrop core. The simulation model does not reproduce the magnitude of the experimentally determined effluent surfactant concentration. This is likely owing to the fact that only water-borne surfactant was measured whereas the larger fraction of the surfactant was expected to be produced in the emulsion or oil phase. Our simulation, however, does not model the emulsion phase but uses a simplified phase behaviour: The optimum salinity (cf. Error! Reference source not found. 11) is calculated from a thermodynamic mixing rule as

p _(opt)(R)=p _(A) ^(1/(1+1/R)) p _(s) ^(1/(1+R)/(1+1/R))

where p_(opt) denotes the optimum salinity as a function of the individual optimum salinities of the petroleum soap (p_(A)) and the surfactant (p_(s)), and the ratio R=(moles of soap)/(moles surfactant). The oil-water partitioning coefficient of the petroleum soap and the surfactant is subsequently assumed to obey a power law of the type

${K\left( {p,R} \right)} = \left( \frac{p}{p_{opt}(R)} \right)^{6}$

which mimics the functional dependence proposed by Liu et al (Liu et al, 2006). It satisfies the condition K(p_(opt)(R),R)=1, i.e. equal partitioning over oil and water at optimum salinity. (cf. Error! Reference source not found. 12).

Piloting

Although, in principle, well understood in the laboratory, there are significant uncertainties around the implementation of ASP in the field. Following successful core flood experiments, a series of Single-Well Chemical Tracer tests has been carried out in three fields (two sandstones, one carbonate) to demonstrate and verify the effectiveness of the selected ASP formulation in the subsurface. In parallel, the objectives and the design for a pattern flood ASP pilot have been developed. Computer simulations were performed to predict injection pressures, liquid rates and effluent concentrations for different pilot configurations.

Series of Single-Well Chemical Tracer Tests

Single-Well Chemical Tracer tests (SWCT) provide a means to establish the immobile oil saturation in a volume extending a few meters out from the well bore into the reservoir. During an SWCT, in essence, one tracer chemical is injected as a finite slug into the well and, subsequently, starts reacting into another tracer chemical in situ. The injected chemical and the in-situ generated chemical have different partitioning characteristics and, therefore, different convection properties depending on the prevalent oil saturation. Hence, after a short shut-in period, upon back-production of the injected slug, they arrive after different times. An interpretation of their resulting effluent concentration profiles yields the remaining oil saturation.

Ideally, each concentration profile exhibits a single maximum. The separation between the maxima of the two profiles relates to the remaining oil saturation through an explicit analytical formula. Deviations from this ideal situation can be caused, for example, by poor well integrity, or by any subsurface rearrangement, during the shut-in period, of the chemical slug, such as well-bore cross-flow or fluid drift. The selection criteria for a well undergoing an SWCT include, therefore, good well integrity as well as a short, single-zone perforation interval and a safe distance from active wells to avoid any interference.

In practice, using existing producing wells with high water-cut may mean that not all selection criteria can be equally well satisfied. Error! Reference source not found. 13 shows the reservoir description log of a well in a PDO sandstone reservoir that was tested by an SWCT. Like most other candidate wells taken into consideration in this field, the selected well features a 30 m wire-wrapped screen completion interval that accesses more than one reservoir. Pressure and rate data as well as the effluent tracer concentration profiles recorded during the SWCT are displayed in Error! Reference source not found. and Error! Reference source not found., respectively. Error! Reference source not found. 13 shows the individual flow periods during the SWCT: a 3000 m³ water-flood followed by a short perforation clean-out production; a 30 m³ chemical tracer slug containing 1 wt.% ethyl formate (EtF) as the injected tracer chemical as well as 0.5 wt. % normal propyl alcohol (NPA) to earmark this slug; a 120 m³ water slug driving the chemical out to 3 m from the well-bore; a two day shut-in period during which EtF partially hydrolyses to from ethanol (EtOH); a 1.2 day back-production period. Both the 30 m³ and the 120 m³ slug were, moreover, tagged by 0.25 wt. % methanol (MeOH). A glance at the effluent tracer concentration profiles shown in Error! Reference source not found. reveals the significant deviation from the ideal situation described above. Reservoir simulation, including a model for the reactive transport of the chemical tracers, suggests that cross-flow between three separate geological layers through the well-bore is responsible for the observed effect. This cross-flow, which was not apparent on a previously run shut-in PLT, occurs as a consequence of the dynamic pressurisation of the individual layers during the tracer injection phase: the lower the total compressibility and the smaller the extent of a layer, the faster its average pressure increases during the injection phase. This can cause an average pressure differential across the layers which rapidly equilibrates, by means of well-bore cross-flow, during the shut-in period. For the particular case of the three-layer model discussed above, the cross-flow required to achieve the match displayed in Error! Reference source not found. amounts to about 10 m³ out of the 6.5 m thick layer, and 4 m³ out of the thick 5.0 m layer, both into the top-most 13.5 m thick layer (cf. caption of Error! Reference source not found.).

Remaining oil saturations of 34% in the 13.5 m layer, and 20% in the other two layers, yielded the best numerical fit which corresponds to a volume average of 28%, in line with expectation for this reservoir.

After this first “base-line” SWCT, 420 m³ of the previously identified ASP formulation were injected into the well followed by a total of 60 m³ tapered polymer drive and 420 m³ water drive. Subsequently, a second SWCT was carried out in the same well to measure the remaining oil saturation and, thus, to assess the efficiency of the ASP formulation. This test was interpreted to yield a remaining oil saturation of 1% (uncertainty range 0-6%). This almost complete desaturation agrees well with the experimental core flood results, suggestion that the reservoir conditions had been suitably reproduced in the laboratory.

Similar sequences were carried out of firstly a base-line SWCT, secondly an ASP injection phase, and thirdly another SWCT, in a total of five wells in three different fields. The first two of these wells were located in a relatively heavy oil high-quality sandstone reservoir; the next two wells were located in two different formations of a medium oil high-quality sandstone reservoir; the fifth well was located in a tight carbonate reservoir. Of the first two wells, which targeted the same formation in the same field, and which stood only 430 m apart, the second well received a smaller ASP slug (44 m³) followed by a polymer drive (131 m³), a short tapered polymer drive (20 m³) and, finally, a long water drive (830 m³). Whereas the base-line SWCT for this second well resulted in a similar remaining oil saturation (25%) as the first well, the final SWCT was interpreted to yield an oil saturation of 23%. Despite the significantly reduced ASP slug this apparent lack of desaturation was unexpected from the experimental core flood results. Pending a closer analysis it is, however, not inconceivable that local reservoir heterogeneity and unstable fluid displacement caused the water-based chemical tracer slug to penetrate through the high-viscosity ASP slug and polymer drive such that, in essence, the SWCT yields once more the original remaining oil saturation prevalent beyond the reach of the ASP treatment. The recorded co-production of diluted alkaline and polymer during the recovery of the chemical tracer slug supports this hypothesis. As a consequence, it may be concluded that the SWCT technique is not suited to determine the efficiency of small (commercial scale) EOR treatments, a lesson heeded for the design of the subsequent tests. The analysis of the results of the latter yet remains to be carried out.

Pattern-Flood Pilot

Whereas the Single-Well Chemical Tracer test series provided evidence for the subsurface desaturation efficiency of the selected ASP formulations it cannot, by design, verify the robustness of the ASP process in a typical flooding application: the stability of the chemicals in the subsurface throughout the duration of a pattern flood; the formation of an oil bank and the stable displacement thereof; the susceptibility to reservoir heterogeneity; the maximum sustainable injection rate of an ASP slug and a polymer drive without uncontrolled fracturing of the reservoir; the commercially optimal volume of these slugs. Further to these subsurface-related uncertainties, significant challenges dominate the surface design of an ASP injection scheme: the formation of carbonate scale or silica scale near producing wells and in the production facilities; the production of emulsified oil at very low oil-water interfacial tension; the supply chain and handling of the involved chemicals.

The main criteria for this work are: the maximisation of data acquisition, such as injectivity, desaturation and recovery factor; the robustness against well or equipment failure; the quantification and mitigation of emulsion and scale formation; a representative geological setting; a feasible pilot duration. Identified risks include the contamination of near-by production wells with ASP chemicals as well as uncontrolled fracturing.

In view of the above, an inverted five-spot pattern (one central injector surrounded by four corner producers) with an edge length of the order of 75 m×75 m is considered the best compromise. Moreover, if desired, this pattern allows an extension of the pilot toward a larger pattern size by converting the corner producers into injectors and drilling four new corner producers at a larger distance surrounding the original pilot pattern. Using the reservoir simulation model calibrated by the aforementioned core flood experiments, ASP forecast simulations have been carried out starting from a current “history-matched” fine-gridded field model. The injection and production rate results are displayed in Error! Reference source not found. 16 while the expected effluent concentration profiles are shown in Error! Reference source not found. Of the total duration of 1.5 years, approximately half a year is spent for the injection of ASP and a polymer drive while the remaining time is used for a subsequent water-flood period. The production of the oil bank is essentially complete after one year of pilot operation. Given that chemical breakthrough occurs after 0.3-0.4 years a part of the oil bank is expected to be produced emulsified, albeit with a comparatively small surfactant concentration. This is owing to the production stream dilution in a single inverted five-spot pattern, and it would not be representative for a field-wide implementation of ASP.

Illustrative Embodiments:

In one embodiment of the invention, there is disclosed a method producing oil and/or gas from an underground formation comprising locating a suitable reservoir in a subsurface formation; creating a model of the reservoir; populating the model with laboratory data; modeling the reservoir to determine fluid displacements based on fluids injected and fluids produced; determining an optimum fluid mixture for the fluids to be injected based on a series of sensitivity analyses performed with the model; drilling a first well in the formation; injecting the optimum fluid mixture into the first well; drilling a second well in the formation; and producing oil and/or gas from the second well. In some embodiments, the first well is at a distance of 25 meters to 1 kilometer from the second well. In some embodiments, the optimum fluid mixture comprises water, a surfactant, a polymer, and an alkali. In some embodiments, the method also includes a mechanism for injecting a water based mixture into the formation, after the optimum fluid mixture has been released into the formation. In some embodiments, populating the model with laboratory data further comprises determining an optimum salinity of a surfactant in the optimum fluid mixture. In some embodiments, populating the model with laboratory data further comprises determining an optimum salinity of a soap formed by a reaction of an alkali in the optimum fluid mixture with the oil in the formation. In some embodiments, drilling a first well further comprises drilling a first array of wells comprising from 5 to 500 wells, and wherein drilling a second well further comprises drilling a second array of wells comprising from 5 to 500 wells. In some embodiments, populating the model with laboratory data further comprises determining a viscosity of the optimum fluid mixture based on a volume of polymer added to the mixture. In some embodiments, the method also includes mixing the optimum fluid mixture prior to injecting the mixture. In some embodiments, the underground formation comprises an oil having a viscosity from 0.5 to 250 centipoise, prior to the injection of the optimum fluid mixture. In some embodiments, the first well comprises a ASP mixture profile in the formation, and the second well comprises an oil recovery profile in the formation, the method further comprising an overlap between the ASP mixture profile and the oil recovery profile. In some embodiments, populating the model with laboratory data further comprises performing a core flood experiment with a core sample from the formation comprising oil from the formation. In some embodiments, performing the series of sensitivity analyses with the model comprises modifying each ingredient in the mixture and determining an optimum value for each said ingredients. In some embodiments, the oil in the formation comprises a first viscosity, and the optimum fluid mixture comprises a second viscosity, the first viscosity is within 75 centipoise of the second viscosity. In some embodiments, the oil in the formation comprises a first viscosity, and the optimum fluid mixture comprises a second viscosity, the second viscosity is from about 25% to about 200% of the first viscosity. In some embodiments, the second well produces the optimum fluid mixture, and oil and/or gas. In some embodiments, the method also includes recovering the optimum fluid mixture from the oil and/or gas, if present, and then optionally re-injecting at least a portion of the recovered optimum fluid mixture into the formation. In some embodiments, the optimum fluid mixture is injected at a pressure from 0 to 37,000 kilopascals above the initial reservoir pressure, measured prior to when injection begins. In some embodiments, the underground formation comprises a permeability from 0.0001 to 15 Darcies, for example a permeability from 0.001 to 1 Darcy. In some embodiments, the method also includes converting at least a portion of the recovered oil and/or gas into a material selected from the group consisting of transportation fuels such as gasoline and diesel, heating fuel, lubricants, chemicals, and/or polymers.

Those of skill in the art will appreciate that many modifications and variations are possible in terms of the disclosed embodiments of the invention, configurations, materials and methods without departing from their spirit and scope. Accordingly, the scope of the claims appended hereafter and their functional equivalents should not be limited by particular embodiments described and illustrated herein, as these are merely exemplary in nature. 

1. A method for producing oil and/or gas from an underground formation comprising: locating a suitable reservoir in a subsurface formation; creating a model of the reservoir; populating the model with laboratory data; modeling the reservoir to determine fluid displacements based on fluids injected and fluids produced; determining an optimum fluid mixture for the fluids to be injected based on a series of sensitivity analyses performed with the model; drilling a first well in the formation; injecting the optimum fluid mixture into the first well; drilling a second well in the formation; and producing oil and/or gas from the second well.
 2. The method of claim 1, wherein the first well is at a distance of 25 meters to 1 kilometer from the second well.
 3. The method of claim 1, wherein the optimum fluid mixture comprises water, a surfactant, a polymer, and an alkali.
 4. The method of claim 1, further comprising a mechanism for injecting a water based mixture into the formation, after the optimum fluid mixture has been released into the formation.
 5. The method of claim 1, wherein populating the model with laboratory data further comprises determining an optimum salinity of a surfactant in the optimum fluid mixture.
 6. The method of claim 1, wherein populating the model with laboratory data further comprises determining an optimum salinity of a soap formed by a reaction of an alkali in the optimum fluid mixture with the oil in the formation.
 7. The method of claim 1, wherein drilling a first well further comprises drilling a first array of wells comprising from 5 to 500 wells, and wherein drilling a second well further comprises drilling a second array of wells comprising from 5 to 500 wells.
 8. The method of claim 1, wherein populating the model with laboratory data further comprises determining a viscosity of the optimum fluid mixture based on a volume of polymer added to the mixture.
 9. The method of claim 1, further comprising mixing the optimum fluid mixture prior to injecting the mixture.
 10. The method of claim 1, wherein the underground formation comprises an oil having a viscosity from 0.5 to 250 centipoise, prior to the injection of the optimum fluid mixture.
 11. The method of claim 1, wherein the first well comprises a ASP mixture profile in the formation, and the second well comprises an oil recovery profile in the formation, the method further comprising an overlap between the ASP mixture profile and the oil recovery profile.
 12. The method of claim 1, wherein populating the model with laboratory data further comprises performing a core flood experiment with a core sample from the formation comprising oil from the formation.
 13. The method of claim 12, wherein performing the series of sensitivity analyses with the model comprises modifying each ingredient in the mixture and determining an optimum value for each said ingredients.
 14. The method of claim 1, wherein the oil in the formation comprises a first viscosity, and the optimum fluid mixture comprises a second viscosity, the first viscosity is within 75 centipoise of the second viscosity.
 15. The method of claim 1, wherein the oil in the formation comprises a first viscosity, and the optimum fluid mixture comprises a second viscosity, the second viscosity is from about 25% to about 200% of the first viscosity.
 16. The method of claim 1, wherein the second well produces the optimum fluid mixture, and oil and/or gas.
 17. The method of claim 1, further comprising recovering the optimum fluid mixture from the oil and/or gas, if present, and then optionally re-injecting at least a portion of the recovered optimum fluid mixture into the formation.
 18. The method of claim 1, wherein the optimum fluid mixture is injected at a pressure from 0 to 37,000 kilopascals above the initial reservoir pressure, measured prior to when injection begins.
 19. The method of claim 1, wherein the underground formation comprises a permeability from 0.0001 to 15 Darcies, for example a permeability from 0.001 to 1 Darcy.
 20. The method of claim 1, further comprising converting at least a portion of the recovered oil and/or gas into a material selected from the group consisting of transportation fuels such as gasoline and diesel, heating fuel, lubricants, chemicals, and/or polymers. 